An earth-boring tool includes a nozzle port extending from an external surface to an internal fluid plenum of a tool body. A fluid inlet sleeve is disposed within the nozzle port of the tool body. The fluid inlet sleeve includes a hollow cylinder having a longitudinal end oriented within the internal fluid plenum. The longitudinal end of the fluid inlet sleeve includes one surface oriented at an angle within a range from greater than 0 degrees to about 90 degrees relative to a plane to which a longitudinal axis of the fluid inlet sleeve is normal.

The present disclosure describes various embodiments, as well as features and aspects thereof, of an improved drill bit assembly for a percussion boring system. More specifically, one non-limiting embodiment of an improved drill bit assembly for a percussion boring system comprises a bit and a product engagement member. The bit comprises a slant faced head and at least one exhaust port. The product engagement member comprises a product coupling portion and at least one fluid restriction portion. This improved drill bit assembly is such that, when the product engagement member is detachably engaged with the slant faced head of the bit, a first portion of the fluid stream expelled from the bit is directed substantially forward of the slant faced head and a second portion of the fluid stream is directed substantially rearward from the slant faced head.

The present disclosure describes various embodiments, as well as features and aspects thereof, of an improved drill bit assembly for a percussion boring system. More specifically, one non-limiting embodiment of an improved drill bit assembly for a percussion boring system comprises a bit and a product engagement member. The bit comprises a slant faced head and at least one exhaust port. The product engagement member comprises a product coupling portion and at least one fluid restriction portion. This improved drill bit assembly is such that, when the product engagement member is detachably engaged with the slant faced head of the bit, a first portion of the fluid stream expelled from the bit is directed substantially forward of the slant faced head and a second portion of the fluid stream is directed substantially rearward from the slant faced head.

Overbalanced drilling (OBD) is known to be cheap and simple but formation damage and reduced rate of penetration (ROP) are some of its disadvantages. However, underbalanced drilling (UBD) minimizes formation damage and achieve high ROP, but it is expensive, complex and can't be applied in many cases.

This application introduces a new technique that incorporates the advantages and avoids the disadvantages of these drilling systems and is referred to as Dynamic Underbalanced Drilling (DUBD).

In DUBD a pressure drop at the environ of the bit, below and around, is created that is restored to normal pressure above the bit and such conditions requires some minor modifications to the design of drill bit. Thus at the zone located below and around the bit underbalance conditions are dominated while the rest of the hole is overbalanced.

The anticipated cost of this technique is nearly zero and it is expected to save much of drilling costs. DUBD is expected to provide higher ROP that may exceed ordinary UBD in some cases, so saves time, reduce formation damage, saves costs (cheaper than OBD) and enables gathering information about the reservoir while drilling. This can save some of logging and testing costs. In addition, DUBD may reduce drilling problems, particularly time sensitive problems, and overcome problems of UBD. Furthermore, it can be used safely in over pressurized shale and salt formations, where UBD is not recommended.

Overbalanced drilling (OBD) is known to be cheap and simple but formation damage and reduced rate of penetration (ROP) are some of its disadvantages. However, underbalanced drilling (UBD) minimizes formation damage and achieve high ROP, but it is expensive, complex and can't be applied in many cases.

This application introduces a new technique that incorporates the advantages and avoids the disadvantages of these drilling systems and is referred to as Dynamic Underbalanced Drilling (DUBD).

In DUBD a pressure drop at the environ of the bit, below and around, is created that is restored to normal pressure above the bit and such conditions requires some minor modifications to the design of drill bit. Thus at the zone located below and around the bit underbalance conditions are dominated while the rest of the hole is overbalanced.

The anticipated cost of this technique is nearly zero and it is expected to save much of drilling costs. DUBD is expected to provide higher ROP that may exceed ordinary UBD in some cases, so saves time, reduce formation damage, saves costs (cheaper than OBD) and enables gathering information about the reservoir while drilling. This can save some of logging and testing costs. In addition, DUBD may reduce drilling problems, particularly time sensitive problems, and overcome problems of UBD. Furthermore, it can be used safely in over pressurized shale and salt formations, where UBD is not recommended.

Systems and methods for drilling a subterranean well with a drill bit include a drill bit body with a central bore. A plurality of ports extend through the nose end of the drill bit body from the central bore to an outside of the drill bit body. A blocked nozzle is located within one of the plurality of ports. The blocked nozzle has a nozzle bore end and a nozzle nose end opposite the nozzle bore end. A bore end disk is located at the nozzle bore end of the blocked nozzle, preventing a flow of fluids through the blocked nozzle past the bore end disk. A nose end disk is located at the nozzle nose end of the blocked nozzle, preventing the flow of fluids through the blocked nozzle past the nose end disk. The nose end disk and the bore end disk are removable.

Systems and methods for drilling a subterranean well with a drill bit include a drill bit body with a central bore. A plurality of ports extend through the nose end of the drill bit body from the central bore to an outside of the drill bit body. A blocked nozzle is located within one of the plurality of ports. The blocked nozzle has a nozzle bore end and a nozzle nose end opposite the nozzle bore end. A bore end disk is located at the nozzle bore end of the blocked nozzle, preventing a flow of fluids through the blocked nozzle past the bore end disk. A nose end disk is located at the nozzle nose end of the blocked nozzle, preventing the flow of fluids through the blocked nozzle past the nose end disk. The nose end disk and the bore end disk are removable.

A well drilling bit for drilling bedrocks includes a columnar bit body, and a drilling fluid flow path formed in the bit body to wash away drilled cuttings from a bottomhole and/or a periphery of the bit body. The flow path is provided with a venturi mechanism including a venturi tube having a reduced-diameter portion where a cross sectional area is reduced and capable of generating a decompression region around a tip of the bit body, the decompression region being more decompressed than a surrounding by the Venturi effect.

A well drilling bit for drilling bedrocks includes a columnar bit body, and a drilling fluid flow path formed in the bit body to wash away drilled cuttings from a bottomhole and/or a periphery of the bit body. The flow path is provided with a venturi mechanism including a venturi tube having a reduced-diameter portion where a cross sectional area is reduced and capable of generating a decompression region around a tip of the bit body, the decompression region being more decompressed than a surrounding by the Venturi effect.

This disclosure presents a downhole device configured as a selectable hole trimmer. The selectable hole trimmer comprises an upper sleeve affixed inside a body via a stop. A charge sleeve is slidable inside the upper sleeve to provide a pressure to a pressurized volume. A catch sleeve is slidable inside the charge sleeve to align a bypsss port and a return port with a drilling mud volume. An actuator is fluidly connected to the pressurized volume via a port. The actuator is configured to provide a pressure to a selectable hole cutter of the body via an actuation port in the transfer sleeve and actuate the selectable hole cutter piston of the selectable hole cutter to move relative to the body, wherein the cutter piston comprises one or more cutters. A manual controller configured to operate the actuator in response to a dropped activation ball.