A wellhead assembly includes an outer wellhead member having a bore and an inner wellhead member located in the bore, defining an annular pocket between the outer and inner wellhead members. A sealing assembly is located within the annular pocket, the sealing assembly having an annular seal and an energizing ring. The energizing ring engages inner and outer legs of the annular seal to push the inner and outer legs into sealing engagement with the inner and outer wellhead members. A retainer nut is threadingly attached to the free end of the outer leg of the sealing assembly. Mating grooves are located on one of an inner diameter of the retainer nut and an outer diameter of the energizing ring and mating protrusions located on the other. The mating protrusions mate with the mating grooves to prevent relative axial movement between the energizing ring and the annular seal.
A subsea wellhead assembly provides a positive indication of landing of a wellhead member and locking of a wellhead member to a wellhead. The subsea wellhead assembly includes at least one positive indicator assembly disposed within a wellhead member, and a communication line extending down a running string from a platform to a running tool disposed in a subsea wellhead. The at least one positive indicator assembly provides confirmation of setting of the wellhead member, and the communication line is in communication with the positive indicator assembly to communicate the confirmation of setting with the platform following setting of the wellhead member.
Embodiments of the present disclosure include an apparatus for forming a tubular fitting includes an annular body having an axial height and radial thickness. The apparatus also includes an inner ami forming at least a portion of the annular body, the inner arm positioned at a first end of the annular body with an inner arm thickness that is less than the radial thickness. The apparatus includes an outer arm forming at least a portion of the annular body, the outer arm positioned at a second end of the annular body with an outer arm thickness that is less than the radial thickness. Also, the apparatus includes one or more self-liniiiing features that control movement of the inner arm and the outer arm relative to one another.
F16L 37/088 - Couplings of the quick-acting type in which the connection between abutting or axially-overlapping ends is maintained by locking members combined with automatic locking by means of a split elastic ring
4.
SYSTEMS AND METHODS FOR MONITORING SUBSEA WELLHEAD SYSTEMS
A system includes a wellhead monitoring system. The wellhead monitoring system includes a processor configured to receive from a sensor a detection of one or more operating parameters associated with a wellhead disposed within a subsea environment. The sensor is coupled to the wellhead, and is configured to detect the one or more operating parameters within the subsea environment. The processor is configured to store the detection of the one or more operating parameters, and to generate an output based at least in part on the detection of the one or more operating parameters. The output includes an indication of an operational fatigue or an operational health of the wellhead.
A system includes a housing section (18, 20) positioned within a wellhead area (14), the housing section (18, 20) also includes a removable wellhead bushing (50) arranged over at least one engagement feature (28) of the housing section (18, 20). The system also includes a Christmas tree (22) including a treehead area (14), the treehead area (14) including a removable treehead bushing (80) arranged over at least one engagement feature (94) of the treehead area (14). The system further includes a tubular (112) extending through both the wellhead bushing (50) and the treehead bushing (80), wherein the tubular (1 12) includes an installation and removal tool (116) adapted to remove at least one of the wellhead bushing (50) and the treehead bushing (80) during wellbore operations.
An annular seal for sealing an interface between a wellhead housing and a casing hanger. The annular seal includes a central body portion and a first pair of seal legs extending in a first direction from the central body portion. Each of the first pair of seal legs sealingly engages one of the wellhead housing or the casing hanger, and are further energized by bore pressure. The annular seal also includes a second pair of seal legs extending in a second direction from the central body portion. Each of the second pair of seal legs sealingly engages one of the wellhead housing or the casing hanger, and is further energized by annulus pressure.
A hydraulic cylinder enclosing a cavity, the cylinder containing a thru hole, an inner cylinder surface, and a longitudinal axis, and a piston within the cavity and movable relative to the cylinder in parallel to the longitudinal axis between a first and second positions. The piston includes a rod extending through the thru hole, the piston attached to the rod and in sealed engagement with the inner cylinder surface, and dividing the cavity into low and high pressure cavities, and each of the low and high pressure cavities containing a hydraulic fluid. The hydraulic cylinder further including a flexible bladder within the high pressure cavity containing a gas and preventing the gas from mixing with hydraulic fluid in the high pressure cavity. The flexible bladder is attached to an end of the cylinder, and is expandable within the high pressure cavity so that when the piston is in the first position, the flexible bladder and the gas are compressed, and as the piston moves toward the second position, the flexible bladder and the gas fill at least a portion of the high pressure cavity.
A wellhead assembly includes a wellhead housing having a bore with a wellhead housing sidewall and a longitudinal axis. A hanger lands in the bore, the hanger having a hanger sidewall. Parallel circumferentially extending hanger sidewall ridges are located on the hanger sidewall. Each of the hanger sidewall ridges have upper and lower flanks that converge to a crest. Hanger sidewall bands are located between adjacent ones of the hanger sidewall ridges. A metal seal ring has an outer seal surface in metal -to-metal sealing engagement with the wellhead housing sidewall and an inner seal surface in metal -to-metal sealing engagement with the hanger sidewall bands. Crests of the hanger sidewall ridges embed into the inner seal surface to restrict relative movement between the hanger and the seal ring. A recess extends through each of the hanger sidewall ridges from the upper flank to the lower flank to allow any fluid trapped between the hanger sidewall ridges to flow out.
A pipe connection includes a pin having circumferentially extending external grooves. A box has an annular base with deflectable fingers extending upward from the base. Each of the fingers has circumferentially extending internal grooves on an inner side and an external thread on an outer side. A collar has an internal thread on an inner side. A radial dimension from the axis to the internal thread crest decreases from turn to turn of the internal thread in a downward direction. The box and the pin are movable from a stab-in position to a locked position in response to rotation of the collar. In the locked position, the external thread crests are in engagement with the internal thread crests, and the internal grooves are in full engagement with the external grooves.
E21B 17/046 - CouplingsJoints between rod and bit, or between rod and rod with ribs, pins, or jaws, and complementary grooves or the like, e.g. bayonet catches
A tubular member connection system (11) includes a box (27) having an inner diameter surface and internal box threads (29). A pin (15) has an outer diameter surface and external pin threads (17), the pin threads shaped to mate with the box threads to releasably secure the pin to the box so that the pin and the box are aligned along a common central axis (16). A slot (35) is located in one of the inner diameter surface and the outer diameter surface, the slot having a pair of side-walls (37). An anti-rotation profile (47) is located in the other of the inner diameter surface and the outer diameter surface. A key (41) is sized to fit within the slot and have a key profile shaped to engage the anti-rotation profile (47) and prevent relative rotational movement between the box and the pin.
A wellhead housing has a bore with an inner seal surface. A hanger with an outer seal surface lands in the bore. Wickers are formed on at least one of the seal surfaces. A metal seal ring lands between the seal surfaces, the seal ring having annular inner and outer legs separated by an annular slot. An energizing ring has inner and outer diameter surfaces that slide against the inner and outer legs of the seal ring when the energizing ring is moved downward in the slot to radially deform the inner and outer legs into sealing engagement with the wellhead housing and hanger. The energizing ring has an inner diameter relief and an outer diameter relief, each being a partially circumferential groove extending upward from a lower rim. The reliefs define a bridge of narrower radial thickness in the lower rim.
Embodiments of the present disclosure include a riser tensioner (11) includes a cylinder barrel (21), a rod (25) reciprocally carried within the cylinder barrel and having an external end sealingly extending out of a proximal end of the cylinder barrel, and a piston (47) on an interior end of the rod that slides and seals against an inner surface of the cylinder barrel. The tensioner further includes a selectively sealed low pressure chamber (51) in the cylinder barrel between the piston and a distal end of the cylinder barrel and tillable with a low pressure fluid, and a selectively sealed annulus (49) between the rod and the cylinder barrel, the annulus extending between the piston and the proximal end of the cylinder barrel and fillable with an annulus fluid at a pressure higher than the low pressure fluid, thereby urging the piston and rod towards retraction.
A wellhead assembly has a casing hanger for supporting a string of casing, the casing hanger having an external upward-facing shoulder. A radially movable annular lockdown member is carried on the shoulder for movement between a retracted position while the casing hanger is being run and an expanded position. In the expanded position, the lockdown member is in engagement with a lockdown profile shoulder in a wellhead housing. A casing hanger seal is carried by the casing hanger above the lockdown member. The casing hanger seal has a lower extension that includes a connection leg and a nose ring. The nose ring has a cam surface that engages and moves the lockdown member to the expanded position while the casing hanger seal is being lowered into a set position. Slots are formed in the extension to reduce the axial stiffness.
The invention provides a powder coating composition comprising of thermoplastic polymers, ceramic particles, and cermet particles for lowering the friction coefficient, and improving wear and corrosion resistance of coated surfaces in high-temperature, high-pressure, and corrosive environments. It also provides a method of coating application for improving adhesion of the coating to the substrate. The coating compositions are devoid of volatile organic solvents and can be applied on surfaces using thermal spraying, compression molding and other particle sintering approaches. A multilayer architecture consisting of an adhesive bottom layer and a non-adhesive, low friction top layer is disclosed. The coating can be used in oil and gas production and seawater injection.
C23C 4/02 - Pretreatment of the material to be coated, e.g. for coating on selected surface areas
C23C 4/04 - Coating by spraying the coating material in the molten state, e.g. by flame, plasma or electric discharge characterised by the coating material
B29C 43/14 - Compression moulding, i.e. applying external pressure to flow the moulding materialApparatus therefor of articles of definite length, i.e. discrete articles in several steps
B05D 7/00 - Processes, other than flocking, specially adapted for applying liquids or other fluent materials to particular surfaces or for applying particular liquids or other fluent materials
F16K 3/00 - Gate valves or sliding valves, i.e. cut-off apparatus with closing members having a sliding movement along the seat for opening and closing
B05D 5/08 - Processes for applying liquids or other fluent materials to surfaces to obtain special surface effects, finishes or structures to obtain an anti-friction or anti-adhesive surface
An external tieback connector secures to a lower end of a driller riser. The tieback connector has a locking element that engages an external profile on the wellhead housing and an actuating piston within a piston chamber. A hydraulic fluid accumulator is in communication with the piston chamber through a hydraulic circuit having valves. An umbilical extends from a floating platform to the accumulator. Sending a signal through the umbilical opens the valves to supply hydraulic fluid pressure from the accumulator to the piston chamber. An acoustic signal receiver also connects to the hydraulic circuit. An acoustic transducer deployed subsea on a transducer cable will emit an acoustic signal that is received by the receiver. The receiver opens the valves to apply hydraulic fluid pressure to the piston chamber.
A system for load transfer from a wellhead to the sea bed (44) adjacent a subsea well (14), including a suction pile (42) for securing to the sea bed, and a wellhead housing assembly (16) having a longitudinal axis (A) and attached to the suction pile (42), the wellhead housing for subjection to an axial load acting in a direction parallel to the longitudinal axis, and a bending load acting in a direction not parallel to the longitudinal axis. The system further includes a suction pile connector (52) that transmits the axial load and the bending load from the wellhead housing (16) through the suction pile toward the sea bed, and that is attached to the suction pile, the suction pile connector(52) engaged with the wellhead housing (16) to substantially maintain the relative positions of the wellhead housing (16) and the suction pile (42).
A tubular member connection system (11) includes a pin (15), external pin threads (17), and an annular pin lip (21) at a shoulder surface (20) of the pin. A box (27) has internal box threads (29) and an annular box lip (31) at an end surface of the box. The box threads are shaped to mate with the pin threads to releasably secure the pin to the box. A pin recess (22) is formed in an outer diameter surface of the pin, the pin recess extending in an axial direction from the pin lip. A pin key (59) is selectively fastenable within the pin recess, the pin key having pin teeth (69) on an outer edge of the pin key. The box teeth (33) are located in the box. The box teeth (33) selectively mate with the pin teeth (69) and resist rotation of the pin relative to the box.
A valve stem packing assembly (33) can seal a valve stem (29) to a valve body (13) having a body cavity (21). The packing assembly includes a packing ring (71) circumscribing the valve stem within a stem opening extending axially through the valve body. A primary dynamic seal (34A) is positioned to seal a dynamic leak path between the packing ring and the valve stem. A secondary dynamic seal (34C) is spaced axially apart and functionally independent from the primary dynamic seal and positioned to redundantly seal the dynamic leak path. A primary static seal (34B) is positioned to seal a static leak path between the packing ring and the valve body. A secondary static seal (34D) is spaced axially apart and functionally independent from the primary static seal and positioned to redundantly seal the static leak path.
F16K 41/08 - Spindle sealings with stuffing-box with at least one ring provided with axially-protruding peripheral closing-lip
F16K 3/02 - Gate valves or sliding valves, i.e. cut-off apparatus with closing members having a sliding movement along the seat for opening and closing with flat sealing facesPackings therefor
F16J 15/3212 - Sealings between relatively-moving surfaces with elastic sealings, e.g. O-rings with at least one lip provided with tension elements, e.g. elastic rings with metal springs
F16J 15/3236 - Sealings between relatively-moving surfaces with elastic sealings, e.g. O-rings with at least one lip having two or more lips with at least one lip for each surface, e.g. U-cup packings
A subsea well connector for connecting a tubular member to a subsea wellhead assembly includes a tieback connector having an annular stationary connector body that circumscribes a portion of an annular moveable connector body. A tie rod with a tie rod profile extends axially from the stationary connector body. A dog ring circumscribes the tie rod and is moveable between a lockdown open position where the dog ring is spaced from the tie rod, and a lockdown engaged position where a dog ring inner diameter profile engages the tie rod profile, to axially couple the stationary connector body and the moveable connector body. An annular piston circumscribes the dog ring and has a region with a reduced inner diameter that engages an outer diameter of the dog ring to retain the dog ring in the lockdown engaged position. A cylinder circumscribes the annular piston, defining a lockdown piston cavity.
A wellhead assembly has a casing hanger (25) for supporting a string of casing, the casing hanger having an external upward-facing shoulder (33), A shoulder ring (41) Is mounted on the shoulder A radially movable annular !ockdown member (37) Is carried on the shoulder ring for movement between a retracted position while the casing hanger Is being run and an expanded position for engaging an Interior surface of a wellhead housing. A casing hanger seal (35) is carried by the casing hanger above the lockdown member. The casing hanger seal has a nose (39) on a lower end that engages and moves the lockdown member to the expanded position while the casing hanger seal is being lowered into a set position. The shoulder ring is formed of a material of greater yield strength than the shoulder. Flow channels between the shoulder and the shoulder ring assist In flowing debris from above the shoulder to below.
A wellhead assembly has a casing hanger for supporting a string of casing, the casing hanger having an external upward-facing shoulder. A shoulder ring is mounted on the shoulder. A radially movable annular lockdown member is carried on the shoulder ring for movement between a refracted position while the casing hanger is being run and an expanded position for engaging an interior surface of a wellhead housing. A casing hanger seal is carried by the casing hanger above the lockdown member. The casing hanger seal has a nose on a lower end that engages and moves the lockdown member to the expanded position while the casing hanger seal is being lowered into a set position. The shoulder ring is formed of a material of greater yield strength than the shoulder. Flow channels between the shoulder and the shoulder ring assist in flowing debris from above the shoulder to below.
A wellhead assembly includes a wellhead housing with a bore and an annular lock groove on an inner diameter surface of the bore. A wellbore member is concentrically located within the bore of the wellhead housing, defining an annulus between the wellbore member and the wellhead housing. An annular lock ring is positioned in the annulus. The annular lock ring has an outer diameter profile for engaging the lock groove and is radially expandable from an unset position to a set position. An energizing ring is positioned in the annulus to push the lock ring outward to the set position as the energizing ring moves downward. A retainer selectively engages the energizing ring and limits axial upward movement of the energizing ring relative to the wellbore member, retains the annular lock in the set position, and prevents axial upward movement of the wellbore member relative to the wellhead housing.
A mechanical lockdown system for a subsea wellhead connector includes a lockdown member or plate that engages with a tie rod that is connected to the wellhead assembly. The lockdown system includes a support member that is permanently secured to an annular ring through which the tie rod passes. The lockdown system also includes a first handle and a second handle that are installed using a plunger or spring loaded system such that mechanical lockdown system can be easily moved from a lockdown open position to a lockdown engaged position as and when desired with minimal ROV interface.
A wellbore system includes a sealing assembly (114, 136) for creating an annular seal between wellbore members. The sealing assembly includes a wicker profile (w) defined on a first sealing surface (120) for engaging and embedding into a radially adjacent, second sealing surface (136). The wicker profile includes a first section (150) having a first hardness and a second section (152) adjacent to the first section and having a second hardness greater than the first hardness. Both the first and second sections of wickers are embedded into the second sealing surface, and can thus provide a high degree of both sealing and lockdown performance.
A wellbore system includes a sealing assembly for creating an annular seal between wellbore members. The sealing assembly includes a wicker profile defined a first sealing surface for engaging and embedding into a radially adjacent, second sealing surface. The wicker profile includes a first section having a first hardness and a second section adjacent to the first section and having a second hardness greater than the first hardness. Both the first and second sections of wickers are embedded into the second sealing surface, and can thus provide a high degree of both sealing and lockdown performance.
A method for tying back a subsea well assembly to a surface platform and a tieback connector used to perform this operation. The tieback connector includes a mandrel having an axis, external threads, an upward facing lip on an external lower end portion of the mandrel, a backup ring having internal threads engaged with the external threads of the mandrel, a sleeve carried on an outside diameter of the backup ring. When the mandrel is rotated relative to the backup ring, the mandrel moves axially upward relative to the sleeve, deforming an annular seal assembly between the upward facing lip of the mandrel and the load bearing surface of the sleeve, thereby creating a seal between the apparatus and the wellhead housing.
A mechanical lockdown system for a subsea wellhead connector includes a lockdown member or plate that engages with a tie rod that is connected to the wellhead assembly. The lockdown system includes a support member that is permanently secured to an annular ring through which the tie rod passes. The lockdown system also includes a first handle and a second handle that are installed using a plunger or spring loaded system such that mechanical lockdown system can be easily moved from a lockdown open position to a lockdown engaged position as and when desired with minimal ROV interface.
A solution based polymer nanofiller composite processing method to improve mechanical, electrical, thermal and/or chemical properties. The solution based synthesis method may include the steps of surface functionalizing carbon nanomaterials and dissolving a polymer in a solvent. The functionalized carbon nanomaterials and dissolved polymer may be mixed until the mixture is homogenous. The mixture may be cured to form the polymer carbon nano-composite material, which provides significant improvements in modulus, hardness, strength, fracture toughness, wear, fatigue, creep, and damping performance.
C08F 2/46 - Polymerisation initiated by wave energy or particle radiation
C08F 2/50 - Polymerisation initiated by wave energy or particle radiation by ultraviolet or visible light with sensitising agents
C08G 61/04 - Macromolecular compounds containing only carbon atoms in the main chain of the macromolecule, e.g. polyxylylenes only aliphatic carbon atoms
C08J 5/00 - Manufacture of articles or shaped materials containing macromolecular substances
C08J 3/215 - Compounding polymers with additives, e.g. colouring in the presence of a liquid phase the polymer being premixed with a liquid phase at least one additive being also premixed with a liquid phase
C08K 7/24 - Expanded, porous or hollow particles inorganic
C08K 9/02 - Ingredients treated with inorganic substances
C08J 5/04 - Reinforcing macromolecular compounds with loose or coherent fibrous material
A wellhead assembly (10) includes an outer tubular wellhead member (12) and an inner tubular wellhead member (16) with a seal pocket (22) between them. A seal ring (30) is located in the seal pocket (22). An annular energizing ring (46) urges the seal ring (30) into sealing engagement with the outer tubular wellhead member (12) and the inner tubular wellhead member (16). A recess (48') is located on an outer diameter of the annular energizing ring (46) or a radially inner diameter of the seal ring (30), and a ratcheted retainer (40) is on the other. A ratchet clip (50') with a clip profile (52) is located within the recess (48'). The recess (48') and the ratchet clip (50') extend less than a full circumferential distance around the outer diameter of the annular energizing ring (46) or the radially inner diameter of the seal ring (30). A retainer profile (42) on the ratcheted retainer (40) selectively engages with the clip profile (52) of the ratchet clip (50').
A tensioner for maintaining a tensile force in a riser extending from a subsea wellhead assembly to a deck of a floating platform includes a hydro-pneumatic assembly having a first section secured to the deck and a second section secured to a support frame. A pivot joint is coupled to the riser and to the support frame, so that the riser is retained axially static with respect to the support frame and is pivotable with respect to the support frame. A guide assembly has at least two guide elements, the guide elements being axially spaced from each other so that when the deck and the support frame move axially relative to each other, the guide assembly restricts relative rotational movement between the deck and the support frame.
A tensioner for maintaining a tensile force in a riser extending from a subsea wellhead assembly to a deck of a floating platform includes a hydro-pneumatic assembly having a first section secured to the deck and a second section secured to a support frame. A pivot joint is coupled to the riser and to the support frame, so that the riser is retained axially static with respect to the support frame and is pivotable with respect to the support frame. A guide assembly has at least two guide elements, the guide elements being axially spaced from each other so that when the deck and the support frame move axially relative to each other, the guide assembly restricts relative rotational movement between the deck and the support frame.
A method for forming an elongated tubular member for use with hydrocarbon production includes forming a blank member of a steel material having an outer diameter equal to a first outer diameter. The blank member is mounted on a rotating mandrel. A tubular member is formed by engaging a rotary disk with an outer surface of the blank member and moving the rotary disk in a first axial direction, lengthening the blank member in a second axial direction and reducing the outer diameter of the blank member until the outer diameter of a central portion of the blank member is equal to a second outer diameter and the outer diameter of end portions of the blank member is equal to a third outer diameter. The tubular member is heat treated to reduce a residual stress. A mechanical connection is formed in each of the end portions.
A tool (10) for testing pressure in a wellhead, having a stem (12) for insertion in the wellhead, the stem having an up position and a down position. The tool (10) further includes an energizing member (14) and an isolation seal (16), so that when the stem (12) is in the down position, the energizing member (14) energizes the isolation seal (16) so that it seals against the wellhead. In addition, the tool (10) includes a plug adapter (20) surrounding the stem (12) and having a variable inner diameter that selectively seals against the stem (12), so that when the stem (12) is in the up position the interface between the plug adapter (20) and the stem (12) is sealed, and when the stem (12) is in the down position, the interface between the plug adapter (20) and the stem (12) is not sealed.
E21B 23/01 - Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells for anchoring the tools or the like
E21B 33/04 - Casing headsSuspending casings or tubings in well heads
A gate valve (10) for use in oil field applications having a seal assembly (78) made up of an elastomeric case (80) and a spring (88) in the case having a V-shaped cross section. The spring has legs (90) that depend from one another, and free ends (94) of the legs that are contoured towards one another to define a rounded surface (96) on outer surfaces of the legs. The rounded surface reduces stress contact between the spring and the case, thereby prolonging seal assembly life. The seal assembly can be placed between a stem (20) in the valve and a gland packing (12). Other seal assembly locations include between a seat ring (32) and counterbore (34) in the valve body.
E21B 34/02 - Valve arrangements for boreholes or wells in well heads
F16K 41/04 - Spindle sealings with stuffing-box with at least one ring of rubber or like material between spindle and housing
F16K 3/02 - Gate valves or sliding valves, i.e. cut-off apparatus with closing members having a sliding movement along the seat for opening and closing with flat sealing facesPackings therefor
35.
INSERT FOR USE WITH WELLHEAD HOUSING HAVING FLOW-BY PATH
A wellhead assembly (36) having an insert (10) that is disposed between a wellhead housing (14) and casing hanger (22). Axial slots (20) through the insert define a flow path between the wellhead housing and casing hanger. The insert is made from a higher strength material and supports a load exerted between the casing hanger and wellhead housing. The insert is a ring like member, and the slots can more easily be machined in the insert than in the wellhead housing.
A wear bushing assembly (20) protects and locks down a hanger (46) in a wellhead housing (45); and which includes a wear bushing body (22) that inserts into a wear bushing sleeve (34). A lock ring (40) extends into registered recesses (42, 44) on the body and sleeve to couple together the body and sleeve. The wellhead housing has a profiled recess circumscribing its inner surface. A lockdown ring (28) selectively mates with the profiled recess; and when mated is in interfering contact with an upper surface of the wear bushing sleeve, thereby coupling the sleeve to the wellhead housing. The sleeve outer surface is profiled to interfere with upward movement of the hanger, so that force is transferred from the hanger to the housing through the sleeve which locks down the housing.
A seal assembly for sealing an annulus between inner and outer wellhead members includes an energizer ring formed of a high strength elastic material having inner and outer legs. An annular inner recess with grooves on its base is formed on an inward facing surface of the inner leg. An inner diameter seal ring formed of an inelastic material engages the grooves of the inner recess. An annular outer recess with grooves on its base is formed on an outward facing surface of the outer leg. An outer diameter seal ring formed of an inelastic material engages the grooves of the outer recess. When the energizer ring is coaxially inserted in the annulus, the inner diameter seal ring is compressively and permanently deformed into sealing contact with the inner wellhead member, and the outer diameter seal ring is compressively and permanently deformed into sealing contact with the outer wellhead member.
A connection is established between a pin connector and a box connector defined on a pair of tubular members such as casing segments in the field of oil and gas recovery. The pin connector and box connector include features for the protection of metallic-sealing surfaces during assembly, disassembly, transport and handling of the tubular members. The pin connector includes a stabbing flank with an inwardly tapered annular flank surface thereon, and an alignment protrusion extending outward with respect to the pin-side metallic sealing surface in a direction normal to a cone angle defined by the inwardly tapered annular flank surface. The alignment protrusion engages internal surfaces of the box connector to concentrically align the pin connector with the box connector, and thereby protects the metallic sealing surfaces from damage that might otherwise result from collisions between the pin connector and the box connector.
Apparatus and methods for tracking a plurality of marine riser assets are provided. Part of a riser lifecycle monitoring system, the apparatus can include an oil and gas riser spider to connect a plurality of riser pipe sections during assembly of a riser pipe string. The riser spider forms an annulus around a first section of the plurality of riser pipe sections and supports the first section of the plurality of riser pipe sections during connection to a second section. The apparatus can also include a reader including an antenna arrangement to read a plurality of radio frequency identification tags, e.g., directional 125 kHz RFID tags, attached to or embedded within an outer surface portion of each of the plurality of riser pipe sections.
E21B 47/12 - Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling
A computer-implemented method is disclosed for characterizing a threaded coupling such as between two tubular members, e.g., casing segments employed in the field of oil and gas recovery. In one embodiment, a virtual model of the coupling is generated, and the virtual model is re-arranged to simulate plastic deformation of at least part of the coupling. The re-arranged model is analyzed to derive a stress/strain distribution of the coupling subject to subsequent loading, and an SAF (stress amplification factor) is determined from the analysis that reflects the effect of cyclic loading of the coupling. The method facilitates a thorough assessment of the performance of the coupling in fatigue.
A retention system for limiting axial and radial movement of a wellbore lock ring (18). The retention system includes pins (20) for resisting axial movement of the lock ring and assemblies for limiting radial outward movement of the lock ring. The lock ring circumscribes and couples to a wellbore hanger (12). The pins project radially from the hanger into the lock ring and into slots (24), where the slots extend a distance along the inner surface of the lock ring. The assemblies also project radially into the hanger and each have a portion that registers with a channel on a lower end of the lock ring. Lock ring outer radial movement is limited by contact between the portions of the assemblies and inner surfaces of the channels.
A wellbore system includes a sealing assembly (124) for creating an annular seal between wellbore members (102, 104). The sealing assembly includes a seal body (126) having a u-shaped cross section, with elongate grooves (144, 148) formed on inner and outer walls thereof. A depth of the grooves varies along a length of the grooves to allow wickers (W) to penetrate the groove by differing degrees when the walls are urged toward the wickers. The wickers can thus provide a high degree of both sealing and lockdown performance.
A wellhead assembly (11) includes a tubular wellhead housing (13) having a bore (15) and an annular gallery slot (23). The annular gallery slot is defined by an enlarged inner diameter of the bore. A tubular hanger (17) is selectively landed in the bore of the wellhead housing, defining an annular cavity (21) between the bore and an outer diameter of the tubular hanger. The tubular hanger is supported by the wellhead housing with a hanger support (19) located in the annular cavity. A flow-by passage (37) is in fluid communication with the annular cavity at locations above and below the hanger support. The flow-by passage intersects with the gallery slot and intersects an outer radial surface of the tubular hanger.
An well assembly having a housing (12) with an inner surface (14), the assembly including a tubular member (18) inserted in the housing and having an outer surface (32). The assembly further includes a plurality of protrusions (38) extending from one of the inner or outer surfaces, the protrusions separated by gaps (40) defined between adjacent protrusions. In addition, the well assembly includes a metal to metal seal (20) pressed against and deformed by the protrusions. A plurality of hollow tubes (42) are provided for insertion in the gaps between the protrusions, the tubes being collapsible upon engagement with the metal to metal seal.
A wellhead assembly (11) includes a wellhead housing (13) having a bore and a locking profile including a gallery slot (23), and an annular notch (31). An inner wellhead assembly (17) is selectively landed in the bore of the wellhead housing, the inner wellhead assembly having a lock ring (33) with a lock ring profile (36) that engages the locking profile. The engaging surface (27) is a sloped downward facing surface at an axially upper end of the gallery slot. The annular notch has a notch engaging profile with a downward facing notch upper shoulder (32a) and an upward facing notch lower shoulder (32b). The locking profile includes an inlay (40), the inlay being located on the notch upper shoulder and the engaging surface.
An well assembly having a housing with an inner surface, the assembly including a tubular member inserted in the housing and having an outer surface. The assembly further includes a plurality of protrusions extending from one of the inner or outer surfaces, the protrusions separated by gaps defined between adjacent protrusions. In addition, the well assembly includes a metal to metal seal pressed against and deformed by the protrusions. A plurality of hollow tubes are provided for insertion in the gaps between the protrusions, the tubes being collapsible upon engagement with the metal to metal seal.
A wellhead assembly (10) including a tubing hanger (18) adapted to be connected to a tubing string and landed in a wellhead (14), and defining a tubing annulus (24) between the tubing string and casing in a well. The wellhead assembly also includes a tubing annulus upper access bore (35) extending downward from an upper end of the tubing hanger, and a tubing annulus lower access bore (33) extending upward from a lower end of the tubing hanger and misaligned with the upper access bore, the lower access bore adapted to communicate with the tubing annulus. A communication cavity connects the upper and lower access bores within the tubing hanger. A remotely actuated valve (26) is in the communication cavity for selectively opening and closing communication between the lower access bore and the upper access bore.
An apparatus for guiding an anti-rotation key installation tool includes at least one magnet mounting member. A tool positioning member is coupled to the magnet mounting member and has a first end and a second end. An installation tool positioning channel extends from the first end to the second end of the tool positioning member and has an opening at the first end of the tool positioning member for accepting a portion of the anti-rotation key installation tool. At least one mechanically switchable frame securing magnet assembly is mounted to the at least one magnet mounting member for releasably securing the apparatus to an outer surface of a tubular connection.
B25B 27/04 - Hand tools or bench devices, specially adapted for fitting together or separating parts or objects whether or not involving some deformation, not otherwise provided for for connecting objects by press fit or detaching same inserting or withdrawing keys
A wellhead assembly includes an inner wellhead member with wickers extending outwardly therefrom and an outer wellhead member with wickers extending inwardly therefrom. A seal assembly having an inner leg and an outer leg is inserted between the wellhead members. An energizing ring forces the legs radially apart from each other. An inlay is located along at least one of an inner diameter of the inner leg and an outer diameter of the outer leg, positioned to sealingly engage the wickers. The inlay is located in a single groove configured so that no part of the seal member body contacts an exterior wall of the inner wellhead member or an interior wall of the outer wellhead member. The inlay has a smooth outer surface flush with the diameter and is made of a material softer than the inner wellhead member, the outer wellhead member, and the seal member body.
A wellhead assembly having a tubular magnetized in at least one selected location, and a sensor proximate the magnetized location that monitors a magnetic field from the magnetized location. The magnetic field changes in response to changes in mechanical stress of the magnetized location, so that signals from the sensor represent loads applied to the tubular. Analyzing the signals over time provides fatigue loading data useful for estimating structural integrity of the tubular and its fatigue life. Example tubulars include a low pressure housing, a high pressure housing, conductor pipes respectively coupled with the housings, a string of tubing, a string of casing, housing and tubing connections, housing and tubing seals, tubing hangers, tubing risers, and other underwater structural components that require fatigue monitoring, or can be monitored for fatigue.
A diverter (10) for redirecting drilling fluid in oilfield applications includes a support housing (14) and a diverter body (18) disposed therein. A lateral opening (20) defined in the diverter body permits fluid communication between an interior passage of the diverter body (18) and a lateral flow outlet defined by the support housing. A pair of flow-line seals (40) disposed radially between the support housing (14) and the diverter body (18) includes a flow-line seal disposed on axially upper and lower sides of the lateral flow outlet (22). The flow-line seals (40) include a pair of substantially rigid support rings (52, 54) and first and second sealing bodies (56, 58) adhered thereto.
A system for jetting a borehole in a seafloor (24), the system including a tubular (16), and a jetting tool (20) inserted into the tubular (16) and having an end from which fluid is selectively discharged to excavate the borehole. An electrical inclination sensor (38) is attached to the stem (21) of the tubular (16), and is in communication a transmitter (40). A receiver (42) is positioned proximate the sea surface and is in communication with the transmitter (40) through the fluid in a drill pipe (18), so that when the jetting tool (20) is excavating the borehole, an inclination of the tubular (16) is sensed by the inclination sensor (38), which inclination is communicated from the transmitter (40) to the receiver (42).
E21B 7/18 - Drilling by liquid or gas jets, with or without entrained pellets
E21B 44/00 - Automatic control systems specially adapted for drilling operations, i.e. self-operating systems which function to carry out or modify a drilling operation without intervention of a human operator, e.g. computer-controlled drilling systemsSystems specially adapted for monitoring a plurality of drilling variables or conditions
53.
Solution based polymer nanofiller-composites synthesis
A solution based polymer nanofiller composite processing method to improve mechanical, electrical, thermal and/or chemical properties. The solution based synthesis method may include the steps of surface functionalizing carbon nanomaterials and dissolving a polymer in a solvent. The functionalized carbon nanomaterials and dissolved polymer may be mixed until the mixture is homogenous. The mixture may be cured to form the polymer carbon nano-composite material, which provides significant improvements in modulus, hardness, strength, fracture toughness, wear, fatigue, creep, and damping performance.
C08F 2/46 - Polymerisation initiated by wave energy or particle radiation
C08G 61/04 - Macromolecular compounds containing only carbon atoms in the main chain of the macromolecule, e.g. polyxylylenes only aliphatic carbon atoms
C07F 7/18 - Compounds having one or more C—Si linkages as well as one or more C—O—Si linkages
C08F 8/00 - Chemical modification by after-treatment
C08J 3/215 - Compounding polymers with additives, e.g. colouring in the presence of a liquid phase the polymer being premixed with a liquid phase at least one additive being also premixed with a liquid phase
C08J 5/00 - Manufacture of articles or shaped materials containing macromolecular substances
C08K 7/24 - Expanded, porous or hollow particles inorganic
A wellbore system (10) includes a housing assembly and first (26) and second (28) position casing hangers supported by the housing assembly. A load member (30) is provided that is adapted to extend between the first position casing hanger and the housing assembly to enable the housing assembly to support the first position casing hanger. The second position casing hanger is stacked onto the first position casing hanger, and an interface (82) is defined between the first and second position casing hangers to aid in alignment and centralization of the second position casing hanger during installation. The interface also provides radial support to the first position casing hanger and enables loads associated with the second position hanger to be transferred to the housing assembly through the load member.
An annular seal (22, 22A) for use in a wellhead assembly (10) has inner (28) and outer (30) legs that each extend in a direction that is generally parallel with an axis of the seal to define an annular space therebetween. Wickers (34, 38) are provided on an outer surface of the seal, so that when the seal is energized and the legs are urged radially apart from one another, the wickers engage with a mating surface of a downhole tubular (16). Embedding the wickers into the tubular creates a flow barrier across the interface between the seal and the tubular. The wickers deform the surface of the tubular, which creates a lock down force that opposes relative axial movement of the tubular.
[0026] A seal system selectively set between coaxial downhole tubulars seals between the tubulars; the system also locks the tubulars together to resist relative axial movement from thermal expansion. The seal system includes a seal element with a nose ring that couples a lock-down ring to both the inner and outer tubulars. Before inserting the seal system between the tubulars, the lock-down ring is disposed in a groove on the inner tubular. Setting the seal system drives a lower tip of the nose ring between the lock-down ring and inner tubular, thereby urging the lock-down ring radially outward. A portion of the lock-down ring remains in the groove, while an outer radial portion of the lock-down ring inserts into a profile on the outer tubular. Axial movement of a tubular transfers force to the other tubular through the lock-down ring, while a minimal amount of force transfers through the seal system.
Systems, apparatus, and program code, and methods for monitoring the health and other conditions of the valve, are provided. An exemplary system for monitoring the condition of the gate valve includes a logic module configured to perform the operations of receiving sensor data providing an acoustic emission, vibration, and/or stream level signature and determining the level of lubricity, level of friction, level of surface degradation, and leakage rate at a gate-valve seat interface. An exemplary method for monitoring the condition of the gate valve includes receiving sensor data providing an acoustic emission, vibration, and/or stream level signature and determining the level of lubricity, level of friction, level of surface degradation, and leakage rate at a gate -valve seat interface.
F16K 37/00 - Special means in or on valves or other cut-off apparatus for indicating or recording operation thereof, or for enabling an alarm to be given
F16K 3/02 - Gate valves or sliding valves, i.e. cut-off apparatus with closing members having a sliding movement along the seat for opening and closing with flat sealing facesPackings therefor
G01N 29/12 - Analysing solids by measuring frequency or resonance of acoustic waves
58.
GATE VALVE ARRANGEMENT INCLUDING MULTI-VALVE STEM AND SEAT SEAL ASSEMBLIES
A gate valve for use in oil field applications and including a stem seal assembly (19) and a seat seal assembly (14). Each of the stem and seat seal assemblies accommodate independent primary, secondary, and tertiary seals for sealing the space between the stem (20) and the bonnet (30), or the seat ring (32 and the valve body (28), respectively. The provision of multiple seals in each assembly provides redundancy that allows for maintenance of the seal between the components even if one or two of the individual seals fail.
F16K 3/02 - Gate valves or sliding valves, i.e. cut-off apparatus with closing members having a sliding movement along the seat for opening and closing with flat sealing facesPackings therefor
F16K 41/08 - Spindle sealings with stuffing-box with at least one ring provided with axially-protruding peripheral closing-lip
A key assembly is press fit into an annular space between a box and pin member to resist relative rotation of the box and pin members. The key assembly includes wedge like members that contact one another along complementary tapered surfaces, and when in contact generate radial forces into the box and pin member to secure the connection between the box and pin. The outer wedge is inserted first into the annular space between the box and pin members, and has rows of elongate teeth that project radially outward into contact with an inner surface of the box member. Because the outer wedge is pushed radially outward against the box member rather than axially sliding therebetween, the teeth protrude into the surface of the box member thereby increasing the anti-rotation force created by the outer wedge.
Apparatus and methods for connecting a linear actuating mechanism of an actuator to a valve stem of a linearly actuated valve, are provided. An example of an apparatus can include an elongate valve stem member (37) of a valve, an extension member (47) of a linear actuating mechanism, a locking cap member (35), and a locking member (33) insertable into the locking cap member (35) for locking the valve stem member (37) with the extension member (47) through employment of the locking cap member (35).
An actuator for operating a linear valve, such as a gate valve, includes a swivel coupling (194) for detachably connecting an indicator stem (150) to a plate (160) within the actuator. In embodiments, the coupling includes a body (196) with a lock ring groove (212). The detachable stem (150) includes a downward facing recess (224) having a groove (228) on an inner diameter surface. The stem (150) is placed on the body (196), and a lock ring (232) engages both grooves (212, 228) to prevent axial movement of the stem (150) relative to the body (196). The lock ring (232) does not, however, prevent rotational movement of the stem (150 relative to the body (196).
F16K 31/122 - Operating meansReleasing devices actuated by fluid the fluid acting on a piston
F16K 31/126 - Operating meansReleasing devices actuated by fluid the fluid acting on a diaphragm, bellows, or the like
F16K 37/00 - Special means in or on valves or other cut-off apparatus for indicating or recording operation thereof, or for enabling an alarm to be given
62.
RATCHETING ANTI-ROTATION LOCK FOR THREADED CONNECTORS
A pipe connection includes a pin having external threads and a box having internal threads. A circumferentially extending row of pin teeth are located on an exterior portion of the pin. A slot extends through a side wall of the box. A key is carried in the slot, the key having a row of key teeth that mate with the box teeth. The key is mounted to the box such that a movable portion of the key is radially movable relative to the box between radially outward and radially inward positions. The key is biased toward the inward position, so that the key teeth ratchet on the pin teeth during make-up of pin and the box. The teeth have a saw-tooth configuration to resist unscrewing rotation of pin and the box. The key may be an integral part of the side wall of the box or a separate component.
A method and apparatus for setting an inner wellhead member in a subsea wellhead housing includes connecting an inner wellhead member to a running tool and running the running tool and wellhead member through a tubular member to a wellhead housing. A plurality of pistons urge fluid through a closed-loop hydraulic system. That fluid actuates a locking mechanism to lock the inner wellhead member into the wellhead housing, and also actuates a release mechanism to release the running tool from the inner wellhead member. The pistons are moved from one position to another in response to fluid pressure from the running string to which the running tool is connected, fluid pressure from the tubular member in which the running tool is located, or in response to fluid in the closed-loop hydraulic system that is being moved in response to the other one of the pistons.
E21B 23/04 - Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells operated by fluid means, e.g. actuated by explosion
E21B 33/04 - Casing headsSuspending casings or tubings in well heads
64.
RADIALLY-INSERTED ANTI-ROTATION KEY FOR THREADED CONNECTORS
A pipe connection includes a box that mates with a pin. A box slot extends through a side wall of the box at a point adjacent the rim for alignment with a pin slot formed on the pin. Each of the slots has a circumferential dimension and an axial dimension that is less than the circumferential dimension. The pin slot has a greater circumferential dimension than the box slot. A locking key has a pin section and a box section located within the pin slot and the box slot, respectively, when the key is installed. The pin section has teeth that bite into the pin slot. The key has a width substantially the same as the circumferential dimension of the box slot.
A tensioner assembly for applying tension to a tubular member, such as a riser, can include an upper latch connected to the tubular member, a platform with a bore, and a lower latch ring. After applying tension to the tubular member, the lower latch ring can be closed around the tubular member so that when the tension is released, the upper latch lands on and engages the lower latch. The assembly can include a locking mechanism that prevents axial movement of the upper latch, relative to the lower latch, after engagement. The upper latch can self-center on the lower latch as it is moved into the latching position.
An assembly (20) for clamping flanged tubular components (10, 14), the assembly (20) including a segmented clamp (22) having a recess (24) configured to accept the flanges (12, 16) of the tubular components (10, 14), and a hole (38) oriented substantially perpendicular to the longitudinal axes of the tubular components (10, 14). The assembly (20) also includes a housing (40) surrounding an outer portion of the segmented clamp (22) and configured for attachment to at least one of the tubular components (10, 14), and a drive screw (50) that passes through the housing (40) and is threadedly engaged with the hole (38) of the segmented clamp (22). As the drive screw (50) rotates, it drives the segmented clamp (22) perpendicularly relative to the tubular components (10, 14) between a locked position, in which the circumferential recess (24) engages the flanges (12, 16) of the tubular components (10, 14), and an unlocked position, in which the circumferential recess (24) is positioned laterally out of engagement with the flanges (12, 16) of the tubular components (10, 14).
E21B 33/038 - Connectors used on well heads, e.g. for connecting blow-out preventer and riser
E21B 17/046 - CouplingsJoints between rod and bit, or between rod and rod with ribs, pins, or jaws, and complementary grooves or the like, e.g. bayonet catches
A wellhead assembly having an outer tubular (12), an inner tubular (14) inserted into the outer tubular (12), an annular space between the inner and outer tubulars, a lock ring (34) in the annular space, and an activation ring (32) that axially strokes between the lock ring (34) and one of the tubulars. The lock ring selectively locks together the inner and outer tubulars when the activation ring slides between the lock ring and the one of the tubulars. The surface of the activation ring that contacts lock ring is contoured so that an interface surface between the activation ring and lock ring when the lock ring is in its locked position, is offset an angle from an axis of the wellhead that is less than an offset between the axis of the wellhead and an interface surface between the activation ring and lock ring when the activation ring is stroking downward.
A seal for sealing an annulus between an outer tubular wellhead member (100) and an inner tubular wellhead member (104) is described. In embodiments, the seal is an annular sealing ring (126) that has a plurality of circumferentially spaced apart sealing ring grooves (144, 148) extending at least from a first end to a second end of the sealing surface (114, 116) of at least one of the wellhead members. When the seal is energized, fouling on the sealing surface is urged toward and then through the slot, axially away from the sealing surface.
A seal assembly for use in a valve that maintains a seal during operational excursions of high temperature, such as during a fire. The seal assembly includes a eutectic material that retains an energizing element in place during normal conditions, which in turn keeps a secondary seal spaced axially away from a sealing position. During high temperature excursions, the eutectic material (38) degrades and releases the energizing element (30). When released, the energizing element (30) energizes a secondary seal (40) that is in an annular space between a valve stem (16) and valve housing (12).
An actuator for operating a linear valve, such as a gate valve, includes a sealing plate that extends across the diameter of a housing. A diaphragm is located on, and fully supported by, the plate. When pressure media urges the diaphragm and sealing plate downward, the sealing plate urges a stem downward to actuate a valve. A hub and an annular support plate can be assembled to form the plate, and the plate can be different sizes by selecting different sized annular support plates.
F16K 31/126 - Operating meansReleasing devices actuated by fluid the fluid acting on a diaphragm, bellows, or the like
F15B 15/10 - Fluid-actuated devices for displacing a member from one position to anotherGearing associated therewith characterised by the construction of the motor unit the motor being of diaphragm type
71.
INTELLIGENT WELLHEAD RUNNING SYSTEM AND RUNNING TOOL
Systems and methods communicating between a subsea running tool (23) disposed within a subsea wellhead (17), a blowout preventer assembly (19), and/or a subsea tree, and a surface platform (25) are provided. An example of such a system includes a running tool assembly. The running tool assembly can include a running tool and a running tool wireless interface (51) carried by the running tool. Wireless interface is configured to communicate running tool sensor data to a blowout preventer assembly wireless interface (45) through a fluid medium located between the running tool wireless interface and a blowout preventer assembly wireless interface when the running tool is operably positioned within a bore extending through a component of the blowout preventer assembly or a bore extending through the subsea wellhead. The wireless communications scheme for communicating with a sensor data can include radiofrequency communications through the fluid medium between antenna components thereof, mutual inductive coupling, backscatter coupling, and/or capacitive coupling.
E21B 47/12 - Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling
Apparatus and methods for managing cementing operations are provided. An example method includes connecting a cementing adapter (51) atop a casing head (31) itself positioned atop a surface casing (33) landed within a conductor pipe (35), connecting a drilling adapter (71) atop the cementing adapter, connecting a blowout preventer (91) to the drilling adapter, and drilling for and running production casing (103). The method also includes positioning a casing hanger (105) at least partially within a bore of the cementing adapter to be immobilized therein to retain back pressure of cement (141) within an annulus (145) located between the production casing and the surface casing, cementing the production casing within the surface casing, and removing the drilling adapter and blowout preventer after running the cement, but typically prior to cement bonding.
Shrinkage compensated seal assemblies and methods of compensating for shrinkage of a seal due to temperature variations, are provided. According to an exemplary shrinkage compensated seal assembly (30), the assembly includes a seal (43), a first compression member (51) for engaging the upper surface of the seal, a second compression member (53) for engaging the lower surface of the seal, and a plurality of pin members (61) each having an elongate body (63) and a head portion (71). The elongate body of each separate one of the plurality of pin members slidably extends through a different one of a plurality of sets of apertures (65, 67, 69) in the first compression member, the seal, and the second compression member to provide for maintaining a substantially constant pressure on the seal at given pressure under varying temperature conditions that result in variations in the volume size of the seal.
F16J 15/12 - Sealings between relatively-stationary surfaces with solid packing compressed between sealing surfaces with non-metallic packing with metal reinforcement or covering
F16J 15/02 - Sealings between relatively-stationary surfaces
F16J 15/06 - Sealings between relatively-stationary surfaces with solid packing compressed between sealing surfaces
F16J 15/16 - Sealings between relatively-moving surfaces
F16J 15/18 - Sealings between relatively-moving surfaces with stuffing-boxes for elastic or plastic packings
A broach-style anti-rotation device for connected tubular members (106; 108) is described. In embodiments, the broach tool (144) is inserted into a slot (118) in an outer diameter surface of the pin (102), and teeth (146) of the broach, which have successively greater height when moving from the front to the tail of the broach, cut a slot (160) in a surface of the box (104). Sidewalls of the broach and its teeth engage shoulders of each slot to prevent the rotation of the tubular members relative to each other.
A back pressure valve for sealing a wellbore. The back pressure valve has a cylindrical body with threads designed to engage threads in the opening of a tubing hanger within the wellbore. The back pressure valve also has a metal sealing surface. When the threads of the back pressure valve engage the threads in the opening of the tubing hanger, the metal sealing surface of the valve seals against the metal of the tubing hanger, forming a metal to metal seal.
A wellhead seal assembly that forms a metal-to-metal seal between inner and outer wellhead members. A metal seal ring has inner and outer legs separated by a slot. An extension of seal ring contacts an upward facing shoulder of the inner wellhead member. An energizing ring with a tapered nose is moved into the slot. The tapered nose has a downward facing stop shoulder that contacts an upper end of inner leg when the energizing ring is in its lower position.
A wellhead assembly for use subsea includes a high pressure housing landed within a low pressure housing. The low pressure housing is an annular member that mounts into the sea floor and having an inner surface engaging the high pressure housing along a loading interface. Upper and lower sockets are formed along axially spaced apart portions of the outer surface of the high pressure housing. As the high pressure housing inserts into the low pressure housing, the high pressure housing sockets engage corresponding sockets formed along axially spaced apart sockets on portions of the inner surface of the low pressure housing. The sockets each have cylindrically shaped outer surfaces, and when engaged with one another define the loading interface. The sockets are strategically located on the upper and lower portions of the housings to maximize their distance apart.
An anti-rotation system for use in retaining a threaded connection between a pin and a box. The anti-rotation system includes a key that sets in a recess formed in one of the box or pin. The key is selectively in contact with one of the other of the box or pin, and is activated when the threaded connection begins to decouple. The key is profiled and operates in a cam like fashion to wedge itself between the box and pin when these members begin to decouple and prevents further relative rotation.
A system (10) for joining pipe segments, the system (10) including a first pipe connector (12) connected to a first pipe segment, and a second pipe connector (14) threadingly connectable to the first pipe connector (12), and connected to a second pipe segment. The system (10) further includes a recess (28) in the outer surface of the first pipe connector (12), and an elongated key (16) having first and second lengthwise surfaces (22, 24). One of the lengthwise surfaces (22, 24) has protrusions (26) that embed into a transverse surface of the second pipe connector (14) when the key (16) is mounted into the recess (28). The thickness of the key (16) decreases with distance radially inward from the outer surface.
A wellhead seal assembly that forms a metal-to-metal seal between inner and outer wellhead members. A seal member has inner and outer seal legs separated by a slot. A locking ring is positioned in the outer seal leg and has wickered sections, where each of the wickered sections protrude through a window in the outer seal leg of the seal member. An energizing ring has an upper tapered surface that is oblique to an axis of the annular energizing ring and extending laterally from the axis over a portion of the locking ring and a lower tapered surface that is oblique to and extending laterally from the axis. As the energizing ring is moved into the slot, the upper tapered surface engages an inner surface of the locking ring, and the lower tapered surface engages an inner annular wall of the slot.
In a wellhead near the top of an oil and gas well, a locking profile (10) configured for locking engagement with an inner well member (16) and including a locking ridge (14) having a rib (18) and a locking shoulder (20). The locking ridge (14) extends radially inward from an inner surface of the wellhead into a well bore. The rib (18) is located on an end of the ridge (14) distal from the wellhead and protrudes into the inner well member (16). The locking shoulder (20) is located on an end of the ridge (14) distal from the wellhead and adjacent a lower end (24) of the rib (18), so that as the inner well member (16) exerts an upward force (F) on the rib (18), the upward force (F) creates a moment (M) in the locking ridge (14) that pushes the locking shoulder (20) into tighter engagement with the inner well member (16).
A downhole tool cleans debris from a subsea well with nozzle assemblies that selectively deploy from the tool. The nozzle assemblies are in fluid communication with an annulus of a drill pipe on which the downhole tool is mounted, so that fluid pumped into the drill pipe discharges from nozzles provided with the nozzle assemblies. The nozzle assemblies are strategically situated so that when deployed, a stream discharged from nozzles on the assemblies clears debris from a surface between a casing hanger and wellhead housing. The nozzle assemblies are coupled to an annular piston coaxially set on the tool; and sliding the piston axially along the tool deploys the nozzle assemblies. Axially spaced apart ports extend radially through the tool to opposing faces on a head of the piston. Blocking one of the ports with a ball dropped down the drill pipe moves the piston and deploys the assemblies.
An energizing ring can be used to energize a seal. In embodiments, the energizing ring has a recess, or divot, adjacent to a portion of the seal so that if the seal is deformed during a balloon- type failure, a portion of the deformed seal can occupy the recess. The seal, thus, engages surfaces of the recess to prevent axial movement of the energizing ring relative to the seal.
A wellhead seal assembly that forms a metal-to-metal seal between inner and outer wellhead members. A seal member has inner and outer walls separated by a slot, where the slot has an upper portion that is wider than a lower portion of the slot. An energizing ring having an upper end portion and a nose is moved into the slot, where the upper end portion has a greater cross-sectional thickness than the nose. As the energizing ring is moved into the slot, the nose of the energizing ring engages the lower portion of the slot to form a lock against the walls of the inner and outer wellhead members, and the upper end portion of the energizing ring engages the upper portion of the slot to form a seal against the walls of the inner and outer wellhead members.
In a wellhead near the top of an oil and gas well, a locking ring (12) assembly for locking an inner tubular wellhead member axially relative to an outer tubular wellhead member. The inner tubular member has a circumferential recess (8) that contains a locking ring. After insertion of the inner tubular member into the outer tubular member, actuating pins (20) radially expand the locking ring so that it partially leaves the circumferential recess and engages a corresponding recess in the outer tubular member. The pins may be deployed by a seal inserted above the inner tubular member, which may be a casing hanger (2).
A pipe connection includes a tubular box having an internal threaded section extending from a rim, and a nose receptacle area joining the threaded section. A box seal surface is formed on the nose receptacle area. A tubular pin has a nose area extending from a pin end, and an external threaded section joining the nose area, the external threaded section mating with the internal threaded section. An annular groove (136) is formed on the nose area between the pin end and the external threaded section. A pin seal surface (132) is located at least partially in the groove for engaging the box seal surface to form a metal to metal sealing engagement.
An actuator (29) for a gate valve (11) having a gate (21) has a stem (37) coupled to a gate (21). A spring (51) is coupled to the stem (37) and has an extended length position while the gate (21) is in a closed position and a contracted length position while the gate (21) is in an open position. The spring (51) has a degressive characteristic such that a graph of a force required to move the gate (21) from the closed position to the open position versus a deflection of the spring (51) is a nonlinear curve with a positive slope that decreases when moving from the closed to the open position. The spring (51) may be an array of wavy springs arranged in nested and in valley-to-crest combinations.
[0019] A seal assembly 22 for use with a casing hanger 24 that includes a pair of split rings 28, 32 held together by a threaded fastener 38. Torqueing the fastener 38 axially compresses one of the rings 28, 32 so that it expands radially inward into sealing engagement with a wall of wellbore 46 casing, and radially outward against an inner wall of a wellhead housing 14. Support grommets 50 are provided where the fastener 38 enters and exits the compressible ring 32. Protrusions 52 on a side of the support grommets 50 project into the compressible ring 32 and create a sealing interface between each support grommet 50 and compressible ring 32. O- rings 56 line inner circumferences of the support grommets 50 to seal between the support grommets 50 and fasteners 38. A threaded end on a lower end of the fastener 38 has a diameter less than an inner diameter of the O-rings 56 to prevent damaging the O-rings 56 during assembly.
A tubular connector secures two coaxial tubulars using a box and pin connection. A pin end tubular member having an axis and a pin end inserts into a box end tubular member having a box end. A pin end flange formed on an outer diameter of the pin end tubular member receives an end of the box end of the box end tubular member. An inwardly depending flange is disposed on the inner diameter of the box end portion. The inwardly depending flange is spaced apart from the box end planar surface and has a box end shoulder formed at an angle to the axis facing a same direction as the box end planar surface of the box end tubular member. An end of the pin end of the pin end tubular member engages with the inwardly depending flange for compressive load transfer.
A tubular connector connects two tubulars of a string of tubular members. The tubular connector has a pin end tubular member having an axis and a pin end. A pin end flange is positioned on an outer diameter of the pin end and has an undercut adjacent the union of the pin end flange with the pin end. The tubular connector also has a box end tubular member having a box end. A box end shoulder is adjacent the union of the box end with the box end tubular member. The box end shoulder has an undercut thereon. The pin end is secured to the box end so that the pin end tubular member and the box end tubular member are joined, stresses applied to the pin end tubular member and the box end tubular member are distributed through the undercuts.
A wellhead assembly having an inner tubular insertable into an outer tubular. A packoff is provided on an outer surface of the inner tubular for sealing between the inner and outer tubulars. The packoff includes an energizing ring, a U-shaped seal member, and a nut for retaining the seal member against the energizing ring. The seal member includes legs that are spaced apart by interaction with the energizing ring. The outer tubular has a bore wall that is profiled so that when the inner tubular is inserted into the outer tubular, an outer leg of the seal member is spaced radially outward from the bore wall until the inner tubular is landed in the outer tubular. A portion of the bore wall tapers radially inwards, such that when the inner tubular member is landed, the outer leg of the seal member is in sealing contact with said portion.
Systems, devices, and methods for providing proper spacing and alignment of multi-well modular drilling templates (31, 32) and associated wells are provided. An example embodiment of a system includes a primary well upon which a multi-well modular drilling template (31, 32) is landed, and a second well (53) upon which a specially configured spacer device (33) is landed. The spacer device (33) includes an alignment frame (111) which engages guide arms (101, 102) of the template to force the spacer device (33) into proper axial alignment. The spacer device (33) includes an elongated arm (69) and a guide funnel (65) which provide the proper spacing and proper location for inserting a third well (55). The third well (55) can be used as the central well for a second multi-well modular drilling template (31, 32).
E21B 43/017 - Production satellite stations, i.e. underwater installations comprising a plurality of satellite well heads connected to a central station
E21B 41/08 - Underwater guide bases, e.g. drilling templatesLevelling thereof
A template 20 for use in positioning subsea wellbores that has a drop away funnel 28 that extends laterally from the template 20. The drop away funnel 28 is used to locate a piling adjacent the wellbores and is selectively detached from the template after installing the piling. A tang and clevis type assembly mounts the drop away funnel 28 to the template 20, where the tang and clevis are coupled together with a main stud. The main stud is oriented substantially parallel with an axis of the drop away funnel 28; so that when the stud is removed, the drop away funnel 28 can decouple from the template and slide axially downward along the piling.
A running tool generates signals in response to setting of a subsea wellhead device that correspond to actual rotation and displacement of the running tool in the subsea wellhead. The running tool includes an encoder that generates a signal corresponding to the number of rotations of a stem of the running tool relative to a body of the running tool. The running tool also includes an axial displacement sensor that generates a signal corresponding to the axial displacement of a piston of the running tool relative to the body. The signals are communicated to the surface using an acoustic transmitter located on the running tool and an acoustic receptor located proximate to a drilling platform at the surface. The signals are communicated to an operator interface device from the receptor for further communication in a manner understood by an operator.
A collet assembly connects two tubular members with a rotation of an outer sleeve. The collet assembly includes a first tubular member with a grooved outer diameter end. The end is inserted into a collet having grooved inner and outer diameter surfaces, and an outer annular sleeve is threaded onto the collet. A grooved outer diameter end of a second tubular member is inserted into the collet. The outer annular sleeve is rotated relative to the collet. The rotation causes the collet to partially disengage from the outer annular sleeve and fully engage the grooves of the ends of the first tubular member and the second tubular member, thereby securing the first tubular member to the second tubular member.
F16L 15/02 - Screw-threaded jointsForms of screw-threads for such joints allowing substantial longitudinal adjustment by the use of a long screw-threaded part
E21B 17/042 - CouplingsJoints between rod and bit, or between rod and rod threaded
A coating for use in protecting surfaces susceptible to environmental degradation. The coating may be applied to metallic surfaces for providing a barrier against elements and/or ambient conditions that would otherwise degrade the surface material. The coating includes multiple layers, where a thermoplastic polymer is included, wholly or partly, within one or more of the layers. Example applications of the coating are for protecting valve seat seals and valve stem seals of a valve assembly used in conjunction with handling of fluids produced from a subterranean formation.
F16K 3/02 - Gate valves or sliding valves, i.e. cut-off apparatus with closing members having a sliding movement along the seat for opening and closing with flat sealing facesPackings therefor
A seal assembly between a wellhead housing having a bore and a casing hanger, has an inner seal leg for sealing against hanger and an outer seal leg for sealing against housing. An extension extends downward from outer seal leg and has a downward facing shoulder that rests on an upward facing shoulder formed on a nose ring. Connection connects seal ring to the nose ring with a lower portion of the nose ring resting on the upward facing shoulder of the casing hanger. Bellows are formed on the nose ring to increase lockdown capacity. Bellows have an inner surface that faces an outer profile of the hanger, and an outer surface on the bellow that faces the bore of the housing. When the bellows are axially collapsed, they expand radially outward and contract radially inward into the bore of the housing and the outer profile of the hanger.
An adjustable casing sub having an outer housing, an inner housing insertable into the outer housing, and a ratcheting system for coupling the inner housing within the outer housing. An annulus is between a portion of the inner and outer housing, the annulus including an inwardly tapered section. A metal faced seal is disposed in the annulus, wherein the metal faced seal includes a sliding surface and a compressive sealing surface. The sliding surface may include a malleable inlay and the compressive sealing surface may include a spring like element. Moreover, the metal faced seal radial thickness is greater than the inwardly tapered section radial thickness.
A subsea wellhead assembly includes a housing with a bore. A hanger is lowered into the housing, the hanger having at least one centralizing finger with a hook for engaging a corresponding hook an activation ring carried by the hanger via a shear pin. A load ring is carried on the hanger and supported initially within a recess formed on the exterior of the hanger. At the correct depth within the housing, coinciding with a shoulder on the inner diameter of the housing, the pin is sheared under the weight of the casing string and the hooks disengage to allow the load ring on the hanger to slide outward and create a path for the casing load to be transferred from the hanger to the hanger load ring, to a housing load ring, and ultimately the housing.
A gate valve seat has structure formed on it to provide a sealing edge or lip which flexes when loaded. The lip forms a dual seal against portions of the gate valve body when the seat is placed under load.
