A bearing capacity reinforcing device. The bearing capacity reinforcing device comprises: a reinforcing mechanism having a reinforcing body and a reinforcing disc connected to a lower portion of the reinforcing body, a plurality of reinforcing rib plates being spaced apart in a circumferential direction of the reinforcing body and connected to the reinforcing disc; wherein the reinforcing disc is provided with a plurality of accommodating spaces which are spaced apart in a circumferential direction thereof and provided therein with a movable sector plate, respectively, and the reinforcing disc at each of the accommodating spaces is provided with a perforated portion which can be blocked by the sector plate; and a connecting portion having a male buckle end connected to a lower end of the reinforcing body, and a female buckle end connected to an upper end of the reinforcing body. The present disclosure can increase the area of action between the riser or the surface conduit and the seabed soil, thereby increasing the bearing capacity of the conduit to ensure the safety and high efficiency of on-site exploration and development operations.

A system, such as a bottom hole assembly, having a central body (18), at least one hydrostatically-actuatable assembly (50) configured to extend radially outward from the central body (18), the hydrostatically-actuatable assembly (50) having at least one N piston body (76) exposed to hydrostatic pressure; a plurality of passive structures (54), each of which is: configured to extend radially outward from the central body (18); and circumferentially spaced from the at least one hydrostatically-actuatable assembly (50) and another one of the plurality of passive structures.

Upset oilfield tubing or upset pump rods are protected from abrasive wear by non-metallic circumferential wear bands applied to the upset portions of the tubing or rods and/or at selected locations along non-upset portions of the tubing or rods between the upset ends. The wear bands may be formed from selected polymeric materials including thermal polyurethane, polyphthalamide PTFE blends, and polyether ether ketone (PEEK), injection-molded onto suitably prepared circumferential surfaces of the tubing or rods. The wear bands may incorporate stainless steel mesh or other reinforcing materials embedded in the injection-molded polymeric material.

Upset oilfield tubing or upset pump rods are protected from abrasive wear by non-metallic circumferential wear bands applied to the upset portions of the tubing or rods and/or at selected locations along non-upset portions of the tubing or rods between the upset ends. The wear bands may be formed from selected polymeric materials including thermal polyurethane, polyphthalamide PTFE blends, and polyether ether ketone (PEEK), injection-molded onto suitably prepared circumferential surfaces of the tubing or rods. The wear bands may incorporate stainless steel mesh or other reinforcing materials embedded in the injection-molded polymeric material.

A sucker rod guide for use in a well production tubing, the sucker rod guide comprising: (a) a sleeve member, including a first material having a first wear characteristic and including: (i) a passage therethrough for a sucker rod; and (ii) an outer surface; and (b) a wear member overlaying the sleeve member and including a second material having a second wear characteristic, the wear member being fixed in position relative to the sleeve member and including: (i) an inner surface; and (ii) an outer surface defining a flow path for a fluid, when in use, between the sucker rod guide and the well production tubing.

A sucker rod guide for use in a well production tubing, the sucker rod guide comprising: (a) a sleeve member, including a first material having a first wear characteristic and including: (i) a passage therethrough for a sucker rod; and (ii) an outer surface; and (b) a wear member overlaying the sleeve member and including a second material having a second wear characteristic, the wear member being fixed in position relative to the sleeve member and including: (i) an inner surface; and (ii) an outer surface defining a flow path for a fluid, when in use, between the sucker rod guide and the well production tubing.

A protective member at least partially surrounds a desired length of pipe (such as a conventional landing string) and protects “umbilical” control line(s) or bundles, including pipe and umbilical line(s) installed within risers of subsea installations. At least one robust protective shell member is installed around at least a portion of a pipe string and forms at least one elongated channel. At least one umbilical control line is disposed within the elongated channel and is shielded against damage from inadvertent or unwanted abrasion, impact or other forces.

Centralizers for stabilizing production tubing within a well may include a mandrel for securing within a section of production tubing and having a gland mounting surface; a gland mounted to the gland mounting surface of the mandrel, and having a cylindrical body and two or more lobes extending radially outward from the cylindrical body and comprised of an abrasion resistant material. Downhole assemblies may include a production string receivable within a cased well; a tubing anchor catcher positioned within the production string; a downhole pump coupled to the production string and located axially below the tubing anchor catcher; and a centralizer coupled to the production string.

Centralizers for stabilizing production tubing within a well may include a mandrel for securing within a section of production tubing and having a gland mounting surface; a gland mounted to the gland mounting surface of the mandrel, and having a cylindrical body and two or more lobes extending radially outward from the cylindrical body and comprised of an abrasion resistant material. Downhole assemblies may include a production string receivable within a cased well; a tubing anchor catcher positioned within the production string; a downhole pump coupled to the production string and located axially below the tubing anchor catcher; and a centralizer coupled to the production string.

A wear support assembly includes a wear pad arranged on top of a support plate, wherein the support plate has a lower surface for connecting to a raise boring tool and both the wear pad and the support plate have at least one hole for receiving a bolt to connect the wear pad to the support plate. Also, a raise boring tool for raise boring operations includes a reamer head having a body, a plurality of roller cutters connected to the body using a holder, a nose or drive stem connected the body, and at least one wear support assembly, wherein each support plate is connected directly to the raise boring tool and each wear pad is radially or perpendicularly bolted to each support plate.